39
CO 2 Capture From Existing Coal-Fired Power Plants Capture Technology Choices and Costs March 6, 2008 Jared Ciferno National Energy Technology Laboratory
CO2 Capture From Existing Coal-FiredPower Plants
Capture Technology Choices and Costs
March 6, 2008 Jared Ciferno
National Energy Technology Laboratory
2
Office of Systems Analysis and Planning (OSAP)Functional Teams
• Systems− oriented toward technologies and processes− focused on systems inside the plant boundary
• Situational Analysis− oriented toward issues and policies− focused on higher-level, macro-systems
• Benefits− oriented toward program metrics− focused on evaluation of R&D programs, assessment of national
benefits, “What if?” Studies
• Extensive Collaboration Among Teams
3
Large Proportion of Total Coal-fired CO2 From Existing Plants
0
500
1,000
1,500
2,000
2,500
3,000
3,500
1995 2000 2005 2010 2015 2020 2025 2030
Unscrubbed SteamUnscrubbed Steam
Scrubbed SteamScrubbed Steam
New SteamNew Steam
IGCCIGCC
Existing units 90.1% of cumulative
coal-fired CO2 2007-2030
(74.6% of year 2030 coal-fired
CO2)
Tons
(mill
ions
)Coal-fired Generation CO2 Forecast
AEO’07 Reference Case
4
If carbon constraints are mandated in the U.S. then…..1. What are the key challenges associated with PC retrofits?
2. What are the CO2 capture technology options available today for existing plants?
3. What are the economics of retrofitting an existing pulverized coal plant with various levels of CO2 capture?
4. Is there a way to significantly reduce CO2 capture cost for the existingfleet?
5. What level of CO2 recovery is economically optimal or necessary to meet proposed regulations?
Key Questions
5
Key Challenges to PC CO2 Retrofits
1. Space limitations — acres needed for current scrubbing2. Major equipment modifications or redundancy3. Regeneration steam availability — can steam turbine operate
at part load?4. Sulfur — additional deep sulfur removal required for most
CO2 sorbents 5. Make-up power — satisfy need to maintain baseload output6. *Local storage availability (saline formation, EOR)7. *Scheduling outages for CO2 retrofits8. *Post-retrofit dispatch implications due to increase in COE9. *Retrofit triggering NSPS review10. *Proposed legislation
6
Existing Pulverized Coal Power Plant
CO2 Capture Challenges:1. Dilute Flue Gas (10-14% CO2)2. Low Pressure CO23. Large volumne—1.5 Million scfm4. 10,000 to 15,000 ton CO2/day5. Large Parasitic Loads (Steam +
CO2 Compression)6. SOx/NOx contaminants
CO2 Capture Challenges:1. Dilute Flue Gas (10-14% CO2)2. Low Pressure CO23. Large volumne—1.5 Million scfm4. 10,000 to 15,000 ton CO2/day5. Large Parasitic Loads (Steam +
CO2 Compression)6. SOx/NOx contaminants
7
Time to Commercialization
Amine solvents
Physical solvents
Cryogenic oxygen
Advancedphysical solvents
Advancedamine solvents
Ammonia
PBI membranes
Solid sorbents
Membrane systems
ITMs
Ionic liquids
MOFs
Enzymatic membranes
CAR process
Chemicallooping
OTM boiler
Biologicalprocesses
Cos
t Red
uctio
n B
enef
it
Present 5+ years 10+ years 15+ years 20+ years
Post-combustion
Pre-combustion
Oxycombustion
CO2 Capture Technology Options
8
Carbon Sequestration From Existing Power Plants Feasibility Study (2007)
Randall Gas TechnologiesRandall Gas Technologies
9
Location: AEP Conesville Unit #5• Total 6 units = 2,080 MWe• Unit #5:
− Subcritical steam cycle (2400psia/1005oF/1005oF)*− Constructed in 1976− 463 MW gross (~430 MW net)− ESP and Wet lime FGD (95% removal efficiency, 104 ppmv)
Ultimate Analysis (wt.%) As Rec’d
Moisture 10.1
Carbon 63.2
Hydrogen 4.3
Nitrogen 1.3
Sulfur 2.7
Ash 11.3
Oxygen 7.1
HHV (Btu/lb) 11,293
Mid-western bituminous coal
10
Detailed Systems Analysis Scope
1. Assess 30%, 50%, 70%, 90% and CO2 capture levels
2. Employ CO2 scrubbing technology advances
3. Detailed steam turbine analysis by ALSTOM’s steam turbine retrofit group
4. Employ CO2 capture and compression heat integration
5. Site visits to specify exact equipment location
6. Include make-up power costs in economic analysis
11
Design Basis: Assumptions
EconomicDollars (Constant) 2006Depreciation (Years) 20Equity (%) 55Debt (%) 45Tax Rate (%) 38After-tax Weighted Cost of Capital (%) 9.67Capital Charge Factor (%) 17.5 Capacity Factor (%) 85 Make-up Power Cost (¢/kWh) 6.40CO2 Transport and Storage Costs not included
12
Existing Plant Modifications
13
Modified FGD Process1. Second stage absorber added to achieve 99.7% SO2 removal efficiency
(6.5 ppmv)2. Estimated EPC cost for each case (30-90%) is $20.5MM3. Includes an SO2 Credit equal to $608/ton in the Variable O&M cost
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Amine Scrubbing Improvements EmployedSince ~2000
Potential Retrofit Options Outcome/Notes1. Heat Integration Steam Consumption
2. Minimize equipment needed Capital cost (ex. No flue gas cooler)
3. Lower cost of materials Capital cost (stainless vs. carbon steel)
4. Structured column packing Capital cost, Sorbent rate (ex. KS1)
5. Plate-and-frame HX Capital cost
6. ANSI Pumps vs. API Pumps Capital cost
7. Vapor-recovery system Steam Consumption
8. Large diameter absorbers # of Absorbers, Capital cost
9. Advanced solvents* Capital cost, Sorbent circ. rate (ex. KS1)
10. Lower re-boiler duty Steam Consumption
*Example:Current amines (MEA) require at least 1,600 Btu/lb CO2 capturedFluor Econamine FG+ requires 1,300-1,400 Btu/lb CO2 capturedMitsubishi’s KS-1 solvent requires 1,200 Btu/lb CO2 captured
15
CO2 Capture Process Parameters
• Reboiler operated at 45 psia—reduced from 65 psia used in 2000 study• Absorber contains two beds of structured packing
Process Parameter Units 2007 2001 AES DesignPlant Capacity Ton/Day 9,350-3,120 9,888 200
CO2 Recovery % 90-30 90 96
CO2 in Feed mol % 12.8 13.9 14.7
SO2 in Feed ppmv 10 (Max) 10 (Max) 10 (Max)
Solvent MEA MEA MEA
Solvent Concentration Wt. % 30 20 17-18
Lean Loadingmol CO2/mol
amine 0.19 0.21 0.10
Rich Loadingmol CO2/mol
amine 0.49 0.44 0.41
Steam Uselbs Steam/lb
CO2 1.67 2.6 3.45
Stripper Feed Temp oF 205 210 194
Stripper Bottom Temp oF 247 250 245
Feed Temp to Absorber oF 115 105 108
Note: Additional data in “notes pages”
16
CO2 Capture Process
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Flue Gas BypassBypass method determined to be least costly method to obtain lower
CO2 recovery levels
CO2 (Moles/hr) Case 1 (90%) Case 2 (70%) Case 3 (50%) Case 4 (30%)
# Trains 2 2 2
FLUE GAS 19,680
1
19,680 19,680 19,680
4,374 13,120
6,560
5,924 13,770
13,766 5,906CO2 PRODUCT 17,720
BYPASS 0
9,822
15,306
8,746
10,934ABSORBER FEED 19,680
STACK 1,962 9,846
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CO2 Capture, Compression, Dehydration, and Liquefaction
CO2 compression to 2,015 psia, EOR specifications
ppmvVol %Wt %Parameter
1000.010.006Moisture
2000.020.03Mercaptans and Other Sulfides
4000.040.03Oxygen
81000.810.3Methane92000.920.6Nitrogen127001.271Hydrogen Sulfide287002.872C2+ and Hydrocarbons94060094.0696Carbon Dioxide
ppmvVol %Wt %Parameter
1000.010.006Moisture
2000.020.03Mercaptans and Other Sulfides
4000.040.03Oxygen
81000.810.3Methane92000.920.6Nitrogen127001.271Hydrogen Sulfide287002.872C2+ and Hydrocarbons94060094.0696Carbon Dioxide
Four Stage Process:
Compression Drying Refrigeration Pumping
Dakota Gasification Pipeline EOR Specification
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CO2 Capture Compression, Dehydration and Liquefaction
1. Compression to 200 Psi 2. Drying to 100 ppmv H2O
3. Refrigeration to -10oF
4. Pump to 2,015 Psia
20
CO2 Capture Process Equipment
CO2 scrubbing technology improvements lead to significant decrease in equipment requirements and capital cost!
CO2 scrubbing technology improvements lead to significant decrease in equipment requirements and capital cost!
2007 Study 2001 Study% CO2 Capture 90 96
ID/Height (ft) No. ID/Height (ft)
34/126 27/126
16/50
Reboilers 10 9
CO2 Compressor 2 7
Propane Compressor 2 7
TIC Cost $MM 370 670
Stripper CW Cond. 12 9
22/50
5
9
1,500 feet
No.
113
131
CO2 Capture Process No.
Absorber 2
Stripper 2
Distance from stack 100 ft
Heat Exchangers No.
Other Heat Exchangers 36
Total Heat Exchangers 58
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Steam Turbine Modifications
Design Assumptions:1. Existing turbine/generator required to operate at maximum load in
case of a trip of the MEA plant− All pressures to be within a level that no steam will be blown off
2. Feedwater system modifications to allow CO2 capture and compression system heat integration− CO2 compressor intercoolers, stripper overhead cooler, refrigeration
compressor cooler
3. Well within the LP turbine “lower load limit” after significant steam extraction for the 90% case (Conesville #5 instruction manual)
4. New Let Down turbine vs. modifying existing LP turbine
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Steam Turbine ModificationsNew Let Down Turbine
Existing 450 MWSteam Turbine
2,853,607 lbm/hr
3,131,619 lbm/hr
514275 lbm/hr
41.7 psia
269,341
kw
640768 lbm/hr
210.0 psia
293 Deg F Boiler
Feed Pump
ExistingGenerator
Existing
HP
Turbine
Existing
IP
Turbine
From SHTR
From RHTR
To RHTR
Existing
DFLP Turbine
DEA
COND
To Boiler ECON
SCAH
To Boiler
De-Sh Spray
195.0 psia
62,081 kW 716 Deg F
1935690 lbm/hr
65 psia
478 Deg F
64.7 psia
298 Deg F
Reboiler Steam
ABB LGI Scope
New Flow Control Valve
NewLetdownTurbine
MEA System
Reboiler
De-Superheater
New Generator
Condensate
Return Pump
1. New LT output between 15 MW (30%) and 62 MW (90%)2. EPC Cost ~ $10MM for each case
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P=90
psi
a
P=47
psi
a
Retrofit solution for 30% Case
Potential solution by properly matching MEA plant requirements and retrofit design
Steam Turbine ModificationsAlternatives to LDT?
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New Equipment Locations Identified
CO2 Absorbers
CO2 Strippers& Reboilers
CO2 Compression
Existing Unit #5 Boiler
Secondary SO2Absorber
Existing Unit #5 Turbine
New Letdown Turbine
Existing Unit #5 SO2 Scrubber
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Plant Electrical OutputPlant Auxiliary PowerPlant Thermal EfficiencyPlant CO2 Emissions
Plant Performance
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Power Output Distribution
434
392363
333303
0
50
100
150
200
250
300
350
400
450
500
Original Plant 90% Capture 70% Capture 50% Capture 30% Capture
Meg
awat
ts
Net BOP CO2 Capture CO2 Compression
463 388 406 424 441
MEASteam
Loss
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Base load (Net) Output ImpactLosses to Grid
0
50
100
150
200
250
300
350
400
450
500
Original Plant 90% Capture 70% Capture 50% Capture 30% Capture
Meg
awat
ts
303MW net
333MW net
363MW net
392MW net
434MW net 131 MW30% Loss
101 MW23% Loss
71 MW16% Loss
42 MW10% Loss
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Plant Thermal Efficiency(HHV Basis)
0
5
10
15
20
25
30
35
40
Original Plant 90% Capture 70% Capture 50% Capture 30% Capture
Net
Effi
cien
cy (%
HH
V)
24%
27%
29%
35%
32%
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CO2 Emissions
0
200
400
600
800
1000
1200
1400
1600
1800
2000
2200
Original Plant 90% Capture 70% Capture 50% Capture 30% Capture
lbm
CO
2/MW
h
2,000
1,550
1,190
780
290
California Proposed
State-of-the-art NGCC
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Capital CostsIncremental COEMitigation CostsSensitivity Analyses
Economics
31
Plant Retrofit Capital Costs
EPC Costs ($1000’s) 2001 2007 Study% CO2 Capture 96 90 70 50 30
Flue Gas Desulfurization 22,265 22,265 22,265 22,265 22,265
New Net Output (kW) 251,634 303,317 333,245 362,945 392,067
$/kW-Original Net Output* 1,616 922 842 647 488
CO2 Capture & Compression 668,277 368,029 333,406 186,694
9,400 8,900
0
280,655
773
0
365,070
1,095
10,516
0
701,057
2,786
134,509
Letdown Steam Turbine 9,800 8,500
Total Retrofit Costs 400,094 211,835
Boiler Modifications 0 0
$/kW-New Net Output 1,319 540
*Original net output = 433,778 kW
53% Reduction in Incremental Capital Costs
Note: Capital costs from 2001 study were escalated to 2006 dollars
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Total Cost of Electricity
0
1
2
3
4
5
6
7
8
9
10
11
12
13
90% Capture 70% Capture 50% Capture 30% Capture
Bas
e Pl
ant C
ost o
f Ele
ctric
ity (¢
/kW
h)
Note: Base power plant cost for the existing plant obtained from Energy Velocity
Base Power Cost = 2.5¢ per kWh
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Total Cost of Electricity
0
1
2
3
4
5
6
7
8
9
10
11
12
13
90% Capture 70% Capture 50% Capture 30% Capture
Bas
e +
Incr
emen
tal C
OE
(¢/k
Wh)
6.65.9
4.94.1
Notes: COE is based off Total Plant Cost (Bare Erected Cost + Project and Process Contingencies); Does not include owner’s costsBase power plant cost for the existing plant obtained from Energy Velocity
Base Power Cost = 2.5¢ per kWh
Capital
Fixed O&M
Variable O&M
Retrofit sub-total COE
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Total Cost of Electricity
0
1
2
3
4
5
6
7
8
9
10
11
12
13
90% Capture 70% Capture 50% Capture 30% Capture
Tota
l Cos
t of E
lect
ricity
(¢/k
Wh)
11.8
9.5
7.2
5.4
Notes: Greenfield plant is a supercritical PCCOE is based off Total Plant Cost (Bare Erected Cost + Project and Process Contingencies); Does not include owner’s costsRetrofit power plant make-up power assessed between 6.40 and 12 ¢/kWhBase power plant cost for the existing plant obtained from Energy Velocity
Retrofit Total COE
Base Power Cost = 2.5¢ per kWh
Capital
Fixed O&M
Variable O&M
Make-up Power(MUPR)
MUPR12 ¢/kWh
MUPR6.4 ¢/kWh
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Total Cost of Electricity
0
1
2
3
4
5
6
7
8
9
10
11
12
13
90% CaptureGreenfieldTotal COE
90% Capture 70% Capture 50% Capture 30% Capture
Tota
l Cos
t of E
lect
ricity
(¢/k
Wh)
11.8
9.5
7.2
5.4
Notes: Greenfield plant is a supercritical PCCOE is based off Total Plant Cost (Bare Erected Cost + Project and Process Contingencies); Does not include owner’s costsRetrofit power plant make-up power assessed between 6.40 and 12 ¢/kWhBase power plant cost for the existing plant obtained from Energy Velocity
Retrofit Total COE
Base Power Cost = 2.5¢ per kWh
Capital
Fixed O&M
Variable O&M
12
Make-up Power(MUPR)
MUPR12 ¢/kWh
MUPR6.4 ¢/kWh
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Economic ResultsCO2 Captured Cost
5964 67
77
5458 61
70
0
10
20
30
40
50
60
70
80
90% Capture 70% Capture 50% Capture 30% Capture
$/To
nne
CO
2 Rem
oved
$/To
n C
O2 R
emov
ed
$/Tonne Removed $/Ton Removed
37
Economic ResultsCO2 Avoided Cost
8996 99
113
8187 90
103
0
10
20
30
40
50
60
70
80
90
100
110
120
90% Capture 70% Capture 50% Capture 30% Capture
$/To
nne
CO
2 Avo
ided
$/To
n C
O2 A
void
ed
$/Tonne Avoided $/Ton Avoided
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1. No major technical barriers found to retrofit with current state-of-the-art scrubbing technology
2. Compared to the 2001 study, this study with an advanced amine (90% CO2 Capture case) showed:• Marked improvement in energy penalty and reduction in
cost
3. Near linear decrease in incremental COE with reduced CO2capture level
4. Sufficient results to answer various definitions of “optimal CO2 capture” from existing plants
1. No major technical barriers found to retrofit with current state-of-the-art scrubbing technology
2. Compared to the 2001 study, this study with an advanced amine (90% CO2 Capture case) showed:• Marked improvement in energy penalty and reduction in
cost
3. Near linear decrease in incremental COE with reduced CO2capture level
4. Sufficient results to answer various definitions of “optimal CO2 capture” from existing plants
Conclusions
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Thank You!
Email: [email protected]: 412-386-5862
NETL Energy Analysis Link:www.netl.doe.gov/energy-analyses
